Identification of Production Potential in Unconventional Reservoirs

Abstract

Abstract Unconventional natural gas systems include fractured shale gas (FSG), tight gas sands (TGS), basin center gas (BCG), shallow basin methane (SBM), and coalbed methane (CBM). Recently, more operators are focusing attention on shale reservoirs. The most notable shale play being developed in the north Texas region is the Barnett shale. This success has encouraged operators to investigate producing potential of the Woodford and Caney shales in Oklahoma. Shale plays are unique in that they often are both the source rock and producing rock contained in the same package. This duality leads to difficulty in log and reservoir interpretation. To date, conventional log interpretation has proved inadequate in identifying producing potential. Simply perforating areas of high porosity and pumping massive hydraulic fracture (MHF) treatments do not always yield commercial production results. Identifying areas of high producing potential using gamma ray, density, resistivity, and sonic transit time to locate high total organic carbon (TOC) has also yielded mixed production results. We believe the addition of mechanical properties of the rock can help identify shale intervals with a high propensity to contain natural fractures and a high probability to create a fracture network during hydraulic fracturing. We propose a linkage between the mechanical properties of the rock and the hydraulic fracture network created during a MHF treatment and the resulting production outcome. Desirable combinations of mechanical properties are selected to help locate areas in the shale that have a propensity to fracture as a network with sufficient aerial extent to impact production results. We use these mechanical properties in addition to TOC and porosity to select fracture initiation sites and give a qualitative assessment of producing capacity. In this paper, we describe calculated log parameters that illustrate this technique. Introduction Finding areas of productive shale is difficult because most logging techniques are based on conventional formations and are calibrated for standard rock types such as limestone, dolomite, or sandstone. The mineral composition of shale is very complex and variation in density, resistivity, and radioactive material content can cause serious errors in porosity and saturation calculations. Specialized logs are used to identify areas of possible hydrocarbon production by locating high total organic carbon (TOC), mature kerogen type III organic material, mineral composition, and areas prone to fracture network development. Identification of these areas is key to successful completion of a shale play. Obtaining a reasonable estimate of shale reservoir quality through logging has evolved by modifying standard log interpretation to fit the complex producing units we call shale. Our initial conceptual model of a shale play as a homogeneous clay-rich, organic source rock is not a valid model. Instead we encounter a multi-layered litho package, comprised of quartz, dolomite, lime, chert, and feldspar, sandwiched in a black shale bulk matrix. These are the shale productive units that most typify commercial Oklahoma shale. Productive shale plays are unique in that they are source rock, reservoir rock, and trap. The primary storage and producing mechanism of shale is a topic of heated debate. In general, most agree that there is a "free" and "adsorbed" component of hydrocarbon present in most shale plays. Exactly where the hydrocarbon is and how it flows out of the rock is still a topic of research. A conceptual model that seems to have some degree of acceptance is one where the "free gas" is stored and produced from micro-porosity in lamina and natural fractures and the "adsorbed gas" is stored and produced from the bulk shale matrix (Fig. 1). The importance of high-resolution log interpretation calibrated to laboratory measurement of mineralogy, organic content, maturation, gas saturation, and mechanical properties is apparent when dealing with multiple storage/flow mechanisms encountered in shale plays. The following will discuss log parameters used to help determine the quality of a producing shale unit. Production potential will be viewed as a mix of geology, geochemistry, mineralogy, hydrocarbon storage and flow, as well as, rock mechanics and its effect on fracture network creation. A commercial shale play will have the necessary mix of all these attributes, and each will have its own impact on the ultimate production.